Offshore Riser Retrofitting Method and Apparatus

ABSTRACT

The invention relates to a method, apparatus and components for adding a riser to an offshore platform. The method may include positioning an L-shaped conduit in the water near the seabed and connecting an upward leg of the conduit to a riser located within the platform jacket through the use of a remotely-operated vehicle (ROV). A standard deepwater connector is used so the ROV can remotely connect the riser to the L-shaped conduit. A horizontal leg of the L-shaped conduit is connected to a pipeline located on the outside of the jacket. The method maybe performed without ceasing production operations of the platform, thereby resulting in significant cost savings. The riser maybe located in a column of conductor guides on the platform jacket. The riser maybe stabilized within the guides, and/or electrically isolated from the platform jacket, through the use of generally semi-circular shaped segmented centralizers or by positioning a bladder between the riser and each guide and then filling the bladder with a material, such as grout or epoxy. The L-shaped conduit may be attached to a skid having one or more inflatable balloons for use in positioning the upward leg of the conduit beneath the riser. Various video, sonar and lighting equipment is disclosed to facilitate the remote connection of the L-shaped conduit to the riser. An assembly station is disclosed on the platform deck for constructing the riser in sections. The riser sections may be welded together in a positive-pressure welding habitat.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention generally pertains to offshore platforms, and moreparticularly to offshore oil or gas platforms in need of beingretrofitted with a riser.

2. Description Of The Related Art

It is known within the oil and gas industry that in certainapplications, depending on the characteristics of a given offshore fieldand the desires of the operator, it may be desirable to retrofit anexisting offshore platform with what is known in the industry as a“riser”. A riser is simply a long pipe or conduit that runs from thedeck of the platform down to the sea floor, where it is connected to apipeline. Oil and gas extracted from beneath the sea floor that isproduced up to the deck of the platform may then be routed down throughthe riser and into the pipeline, which transports the oil and gas toanother location (e.g., another platform or land) for furtherprocessing.

The current method of retrofitting a riser to an existing platform is toattach the riser in sections to the outside of the platform jacket. Thisis done using divers who bolt the pipe sections together to form theriser and attach it to the platform jacket. As shown in FIG. 1, aplatform 10 generally includes a deck 12 and a jacket 14. The jacket 14is the support structure for the deck 12. The jacket 14 rests on theocean floor 16. FIG. 1 illustrates a riser 18 that has been attached tothe exterior of the jacket 14. The riser 18 is connected to a pipe line20 running along the ocean floor 16.

One problem with the current approach to retrofitting a riser 18 to anexisting platform 10 is that safety concerns require that production bestopped during the time that the riser 18 is being attached to thejacket 14. One reason for this is because divers are used to bolt andattach the riser 18 to the outside of the jacket 14. Another reason forshutting down production is the potential for a section of the riser tobe dropped on an existing pipeline, thereby rupturing it and creating ahazardous environment. The production downtime is extremely costly tothe oil field operator. For example, it would not be uncommon for theoperator to lose millions of dollars for each day of downtime.

Another problem with the current retrofitting method is that the numberof days of downtime depends on site conditions, such as weather and waveactivity. For example, these site conditions may require the crew tohalt the retrofitting operation until the conditions improve. In thesesituations, the operator is at the mercy of the weather, for example,until the weather clears. Not only is millions of dollars of productionbeing lost for each day of inactivity, but leased equipment must be paidfor while waiting for the site conditions to improve. This equipmentlease cost can easily add hundreds of thousands of dollars per day tothe retrofitting tab.

As explained more fully below, the present invention is directed to anew and improved approach to installing a riser to an offshore platform.The present invention does not require termination of production duringthe installation operation. As such, it is believed that the use of thepresent invention will result in millions of dollars of cost savings tothe operator.

SUMMARY OF THE INVENTION

In one aspect, the present invention may be a method of establishing afluid flow path from a deck of an offshore platform supported by ajacket to a pipeline located in a body of water beneath the deck,comprising: positioning a conduit in the body of water below the deck,the conduit having a first end located within the jacket and a secondend located outside of the jacket; constructing a riser having an upperend and a lower end; positioning the riser within the jacket with theupper end located at the deck; and connecting the lower end of the riserto the first end of the conduit. Another feature of this aspect of theinvention may be that the method further includes performing each of thesteps without ceasing production operations of the platform. Anotherfeature of this aspect of the invention maybe that the method furtherincludes connecting the second end of the conduit to the pipeline.Another feature of this aspect of the invention may be that the methodfurther includes establishing fluid communication between the upper endof the riser and a source of hydrocarbons below the body of water.Another feature of this aspect of the invention may be that the methodfurther includes positioning the riser within a plurality of conductorguides on the jacket. Another feature of this aspect of the inventionmay be that the method further includes stabilizing the riser within theconductor guides. Another feature of this aspect of the invention may bethat the method further includes positioning a pair of generallysemi-circular shaped centralizer members in an annulus formed betweenthe riser and each conductor guide. Another feature of this aspect ofthe invention may be that the method further includes filling an annulusbetween the riser and each conductor guide with a material and allowingthe material to set. Another feature of this aspect of the invention maybe that the material is at least one of a grout and an epoxy. Anotherfeature of this aspect of the invention may be that the method furtherincludes electrically isolating the riser from the jacket. Anotherfeature of this aspect of the invention may be that connecting the lowerend of the riser to the first end of the conduit is performed withoutthe use of a diver. Another feature of this aspect of the invention maybe that connecting the lower end of the riser to the first end of theconduit is performed with a remotely operated vehicle. Another featureof this aspect of the invention maybe that the method further includesconnecting at least one inflatable bladder to the conduit and remotelycontrolling the pressure in the bladder to assist in positioning thefirst end of the conduit adjacent the lower end of the riser conduit.Another feature of this aspect of the invention may be that the methodfurther includes an enclosure containing the inflatable bladder. Anotherfeature of this aspect of the invention may be that the method furtherincludes using a diverless connector to connect the lower end of theriser to the first end of the conduit. Another feature of this aspect ofthe invention may be that the method further includes using a lightsource to align the lower end of the riser with the first end of theconduit.

In another aspect, the present invention may be an apparatus forconnecting a generally vertical riser within a jacket of an offshoreplatform to a pipeline located outside of the jacket, comprising: aframe; and a generally L-shaped conduit attached to the frame, theL-shaped conduit having a first end adapted for connection to a lowerend of the riser conduit and a second end adapted for connection to thepipeline. Another feature of this aspect of the invention may be thatthe apparatus further includes at least one remotely-controllableinflatable bladder adapted to assist in positioning the first end of theconduit adjacent the lower end of the riser. Another feature of thisaspect of the invention may be that the apparatus further includes adiverless connector connected to the first end of the L-shaped conduitand a mating connector connected to the lower end of the riser.

In still another aspect, the present invention may be an apparatus forconstructing a riser comprising: a support base; a tower rotatablyattached to the base and moveable between a lower position and an upperposition; a top clamp movably attached to the tower; a bottom clampattached to the support base, and aligned with the top clamp when thetower is in its upper position; and an enclosure having an open positionand closed position, the enclosure being positioned between the bottomclamp and the top clamp when the enclosure is in its closed position.

The above summary of the invention is not intended to, nor does it,attempt to summarize all aspects of the present invention. Otherfeatures, aspects and advantages of the present invention will becomeapparent from the following discussion and detailed description.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a side view of a prior art offshore platform showing that ariser that has been retrofitted to the outside of the platform.

FIG. 2 is a side view showing one embodiment of the present invention.

FIG. 3 is an end view of a specific embodiment of a tube turn skid ofthe present invention.

FIG. 4 is a side view in cross section illustrating how a riser of thepresent invention may be centrally stabilized in a conductor guideand/or electrically isolated from an offshore platform jacket.

FIG. 5 is side view in partial cross-section showing another embodimentof the present invention.

FIG. 6 is a side view showing another embodiment of a tube turn skid ofthe present invention.

FIG. 7 is a top view of the tube turn skid shown in FIG. 6.

FIG. 8 is an end view of the tube turn skid shown in FIGS. 6 and 7.

FIG. 9 is a side view in partial cross section of an offshore platformwith the tube turn skid being lowered into position.

FIG. 10 is another view similar to FIG. 9, showing the tube turn skidattached to a number of winches and being moved into position.

FIG. 11 is another view similar to FIGS. 9 and 10, showing additionalcables located adjacent a column of conductor guides and connected tothe tube turn skid to assist in locating the skid in its desiredposition for connection to the jacket and the riser.

FIG. 12 is a top view showing the tube turn skid in position asillustrated in FIG. 11.

FIG. 13 is a side view showing a platform crane and a vertical stalkingstation located on an upper deck of the offshore platform, with thevertical stalking station in its upright position.

FIG. 14 is a side view similar to FIG. 13, except that the verticalstalking station is shown in a lowered or horizontal position and withthe crane being used to load a section of riser pipe or conduit onto thevertical stalking station.

FIG. 15 is a side view in partial cross-section of a section of pipe orconduit used to form a riser according to the present invention, such asthe conduit illustrated in FIG. 14.

FIG. 16 is a side view similar to FIGS. 13 and 14, showing the cranebeing used to raise the vertical stalking station from its loweredposition to its upright position.

FIG. 17 is a side view similar to FIGS. 13, 14 and 16, showing thevertical stalking station in its upright position and with the sectionof riser pipe being lowered.

FIG. 18 is a side view similar to FIGS. 13, 14, 16 and 17, showing thefirst section of riser pipe lowered into engagement with a bottom clampon the vertical stalking station.

FIG. 19 is a side view similar to FIGS. 13, 14, 16, 17 and 18, showing anext section of riser pipe being held in position by the verticalstalking station above and in aligned contact with the section of riserpipe located in the bottom clamp, and with a welding habitat rotatedaround the joint formed by the two sections of riser pipe to be weldedtogether.

FIG. 20 is a top view of a horizontal joint support on the verticalstalking station and shown in a closed or clamped position.

FIG. 21 is a top view of the horizontal joint support shown in FIG. 20,only in FIG. 21 the horizontal joint support is shown in an openposition.

FIG. 22 is a top view of the welding habitat in a closed position.

FIG. 23 is a top view of the welding habitat showing it being rotated toan open position.

FIG. 24 is a top view of a specific embodiment of a top clamp on thevertical stalking station, and shown in an open position.

FIG. 25 is a top view of the top clamp shown in FIG. 24, but shown inFIG. 25 in a closed or clamped position.

FIG. 26 is a top view of a specific embodiment of a bottom clamp on thevertical stalking station, and shown in an open position.

FIG. 27 is a top view of the bottom clamp shown in FIG. 26, but shown inFIG. 27 in a closed position.

FIG. 28 is a side view showing the top clamp of FIGS. 24 and 25 beinglowered down towards the bottom clamp shown in FIGS. 26 and 27.

FIG. 29 is a side view similar to FIG. 28, but showing the top clamplowered down to a position adjacent the bottom clamp.

FIG. 30 is a top view of the top clamp positioned above the bottomclamp.

FIG. 31 is an end view of the top clamp and bottom clamp as shown inFIG. 28.

FIG. 32 is an end view of the top clamp and bottom clamp as shown inFIG. 29.

FIG. 33 is a side view showing a pair of centralizer segments shown inspaced apart relation.

FIG. 34 is a top view of the centralizer segments shown in FIG. 33.

FIG. 35 is a side view showing the centralizer segments shown in FIGS.33 and 34 disposed within a conductor guide on a platform jacket andwith a riser disposed therethrough.

FIG. 36 is a top view of the view shown in FIG. 35.

FIG. 37 is a side view showing an annular bladder being positionedaround a riser and within a conductor guide to be used to hold ahardenable material such as grout or epoxy to stabilize the riser withinthe guide.

FIG. 38 is a top view of the configuration shown in FIG. 37.

FIG. 39 is a side view similar to FIG. 37, only showing the bladderafter it has been filled.

FIG. 40 is a top view of the configuration as shown in FIG. 39.

While the invention will be described in connection with the preferredembodiments, it will be understood that it is not intended to limit theinvention to those embodiments. On the contrary, it is intended to coverall alternatives, modifications, and equivalents as may be includedwithin the spirit and scope of the invention as defined by the appendedclaims.

DETAILED DESCRIPTION OF THE INVENTION First Embodiment

Referring to the drawings in detail, wherein like numerals denoteidentical elements throughout the several views, there is shown in FIG.2 an offshore platform 11 and one embodiment of the present inventionwherein a riser 19 is installed, without terminating production, insideof or down the interior of a jacket 21 of the platform 11 utilizing anexisting unused drilling conductor “slot”. FIG. 2 further shows apipeline connection assembly or tube turn skid 22 (see dashed lines)that is provided to connect the bottom of the riser 19 (located insidethe jacket 14) to a pipe line 23 (located outside the jacket 21).

In one embodiment, the present invention may rely on or make use ofexisting structure located on the platform 11. As is well known to thoseof skill in the industry, drilling and production platforms aretypically constructed with a number of “routes” or “channels” throughwhich drilling string and production tubing (not shown) may be directeddown inside the jacket 21 and into the ocean floor 17. If it is desiredto use one of the routes in a drilling or production operation, a“conductor” (which is a pipe, not shown) is fed from a deck 13 of theplatform 11 (in sections) down through conductor guides 24 (which aresometimes like funnels) corresponding to the particular slot selected.The conductor (not shown) is fed (in sections) down to and driven intothe ocean floor 17. Drilling string (not shown) is then passed downthrough the conductor to drill the well. After the well has been drilledand the drilling string is removed, production tubing (not shown) isinstalled through the conductor to complete the well and produce thehydrocarbons to the platform 11. This background on conductors is merelyprovided for a background understanding of the purpose of the conductorguides 24.

In one aspect of the present invention, the guides 24 maybe utilized fora different purpose. With reference to FIG. 2, it can be seen that theriser 19 is fed down through the guides 24, and then connected to thetube turn skid 22 via a connection 26. As will be discussed furtherbelow, the connection 26 may be any type of connection in which twosections of pipe or conduit may be remotely connected through the use ofa Remotely Operated Vehicle (“ROV”). One example of an industry-standardconnection, which has been used in ultra-deepwater diverlessapplications, may be a collet connection assembly of the type availablefrom Cameron International Corporation, of Houston, Tex. Other knownconnectors may be of the type available from FMC Corporation, ofHouston, Tex., or Oil States Industries, of Arlington, Tex., forultra-deepwater/ROV applications.

The tube turn skid 22 is preferably placed into its position before theriser 19 is lowered down through the guides 24. The skid 22 can belowered into position through the use of a platform crane and winches(not shown), as more fully discussed below. The tube turn skid 22 mayinclude a generally L-shaped section of pipe 28 mounted to a supportframe 30. The L-shaped section 28 preferably includes a bend ofsufficient diameter to allow traditional pigging equipment to passtherethrough, as will be understood by those of skill in the art. Partof the connection 26 (denoted as 26 a) may be connected to theupstanding vertical portion of the L-shaped member 28. The other end ofthe L-shaped member (i.e., the end of the horizontal section of theL-shaped member 28) may be provided with a flange 36 and positionedoutside of the jacket 21. The flange 36 is of any known type used forconnecting a riser to the pipe line 23. Attached to the frame 30 maybe adownwardly extending stabbing connector 32 adapted for engagement with alowermost guide 34 on the jacket 21 at the mudline level, if available.The stabbing connector 32 may be a pipe that is disposed in co-axialrelationship with the vertical end (i.e., where the connection part 26 ais located) of the L-shaped member 28.

As best seen in FIG. 3, which is an end view of one sample embodiment ofthe tube turn skid 22, it can be seen that the frame 30 may includeupstanding side members 38 adapted to contain inflatable balloons orbladders 40 that may be secured to the side members 38. As more fullydiscussed below in connection with another embodiment of the presentinvention, a mesh covering may be provided to contain the balloons 40 tocontrol their volume and assist in controlling the buoyancy of the skid22, as more fully discussed below.

The installation process is preferably commenced by lowering the tubeturn skid 22 from the deck 13 down to or near the ocean floor 17. Atthat point, the balloons 40 are inflated, through the use of an ROV,until neutral buoyancy is achieved. (In actuality, as is known in theindustry, neutral buoyancy actually means slightly negative buoyancy, sothe part to which the balloons are attached will not rise to the watersurface.) Rigging cables (not shown in FIG. 2) are also preferablypassed downwardly and connected to the top of the curved portion of theL-shaped member 28. The ROV (not shown) can then grasp the tube turnskid 22 and maneuver it, assisted by the rigging cables, from outsidethe jacket 21, through an opening in the jacket 21, to its desiredposition inside the jacket 21. As shown in FIG. 2, the stabbingconnector 32 on the bottom of the frame 30 when available may be stabbedinto engagement with the lowermost guide 34. It is noted that if thesite conditions worsen (e.g., unexpected strong water currents) duringthe process of moving the tube turn skid 22 from outside the jacket 21to inside the jacket 21, the balloons 40 may be deflated to lower theskid 22 to the ocean floor 17 until conditions improve. As more fullydiscussed below in connection with another embodiment, an umbilicalcontaining various hoses and cables is provided to remotely operatevarious items of equipment preferably provided to connect the riser 19to the skid 22 (e.g., sonar, video, hydraulic, load cells, green laserfan alignment lights, etc.).

Next, after the skid 22 is properly positioned, the rigging cables areremoved, and the riser sections are then serially welded and lowereddownwardly through the use of an assembly station 42 located on the deck12. The station 42 may include, for example, structure similar to aJ-Lay tower of the type that has been proven for use on barges, and apositive-pressure welding station or habitat. The riser sections areserially held in place by the station 42 and welded inside the weldinghabitat to the riser 19, which is gradually lowered downwardly throughthe guides 24. The lower end of the riser 19 may include a part 26 b ofthe connection 26, which may be remotely engaged, through the use of theROV and various video and sonar feeds with the umbilical, to the part 26a of the connection 26, which is attached to the top of the L-shapedpipe 28. The flange 36 on the end of the horizontal portion of theL-shaped member 28 may then be connected to the pipe line 23 in a knownmanner.

It is also preferable that the riser 19 be stabilized within theconductor slots 24 and/or electrically isolated from the jacket 21. Asshown, for example, in FIG. 4, this may be accomplished by positioningarcuate wedge sections 44 in the annulus formed between the riser 19 andthe guides 24. It is noted that the size of the annulus will depend onthe size of the pipe used for the riser 19 and the size of the conductorslots 24. The wedge sections 44 are preferably provided with a suitablematerial 46 (e.g., neoprene) to engage the riser 19 to electricallyisolate the riser from the jacket 21. In another embodiment, as morefully discussed below, a hardenable filler material, such as grout orepoxy, for example, may be positioned through the use of an annularbladder in each annulus between the riser 19 and the guides 24.

Second Embodiment

Another embodiment of the present invention will now be described withreference to FIGS. 5-40. Referring to FIG. 5, an offshore platform 50includes a jacket 52 resting on the ocean floor 54. The platform 50 mayfurther include an upper deck 56 and a lower deck 58, both positionedabove the ocean water surface 60. The platform 50 is provided with aplatform crane 62. A vertical stalking station 64 is shown mounted onthe upper deck 56, which will be described in more detail below inconnection with FIGS. 9-16. The platform 50 may be provided with one ormore conductors 66 positioned within guides 67 for use in drilling awell in and/or producing hydrocarbons from beneath the ocean floor 54.

The platform 50 further includes a welded vertical riser string (orriser) 68 that has been installed through the use of the verticalstalking station 64. The riser 68 is positioned down through theinterior of the jacket 52, as opposed to on the outside of the jacket52. Again, the riser 68 may be installed without ceasing production inorder to eliminate downtime costs. Attached to the lower end of theriser 68 is a tube turn skid 70, which will be described in more detailbelow in connection with FIGS. 6-8. The tube turn skid 70 is shownconnected to the lower end of the riser 68 via a diverless connection106 (e.g., a proven industry-standard collet connector of the typediscussed above). The platform 50 is preferably provided with segmentedcentralizers 74 within each guide 67 through which the riser 68 ispassed to centrally stabilize the riser 68 within the guides 67 and/orelectrically isolate the riser 68 from the jacket 52. The centralizers74 are more discussed below in connection with FIGS. 33-36.Alternatively, as explained above and discussed more fully below inconnection with FIGS. 37-40, the riser 68 may be stabilized andelectrically isolated within the guides 67 through use of an annularbladder filled with a material such as grout or epoxy, for example.

The platform 50 is also preferably provided with a fusion bonded epoxy(FBE) application habitat 76 below the vertical stalking station 64(e.g., between the upper deck 56 and lower deck 58) to apply FBE or anyother suitable field joint corrosion coating to the welded joints of theriser 68. After the riser 68 has been welded and installed intoposition, the upper end of the riser 68 is preferably engaged with atemporary support friction clamp 78 of a type known in the industry tohold the riser 68 in place after it is disconnected from the stalkingstation 64 until it can be tied-in to a production manifold by amechanical contractor.

The platform 50 may also be provided with a number of winches 82 (e.g.,air and/or hydraulic winches), each having a cable 84 that may be usedin positioning the tube turn skid 70. A platform-based work-classremotely-operated vehicle (ROV) 86 of the type known in the industry(e.g., a 100 horsepower ROV) is also provided to assist in positioningthe tube turn skid 70 and make the necessary connections at the skid 70.The size of the ROV 86 should be selected in light of the capacity ofthe crane 62 so that the crane 62 is able to lift the ROV 86 to decklevel from a supply boat. The platform 50 may also be provided with asonar/video system 88 to enable surveillance of the positioning andconnecting of the skid 70. The skid 70 is also provided with anumbilical 90 running from the upper or lower deck 56 or 58 to the skid70. The umbilical 90 may include a variety of cables or conductors, suchas for air, hydraulics, light power, load cell and video feeds, forexample. The umbilical 90 is preferably connected to a control panellocated, for example, on one of the decks 56 or 58, to enable anoperator, such as at deck level, to remotely operate the necessaryequipment to position and make the necessary connections to the skid 70.

The Tube Turn Skid

The tube turn skid 70 shown in FIG. 5 will now be described in moredetail in connection with FIGS. 6-8. Referring to FIG. 6, the tube turnskid 70 may include a support frame 92 and a conduit 94 having a riserend 96 and a flange end 98. The skid frame 92 is preferably configuredto rest on bracing at the bottom of the jacket 52. Depending on thedesired placement of the skid 70 on the jacket bracing, it may benecessary to use the ROV 86 to remove anodes attached to the jacketbracing for later relocation by pipeline divers. The frame 92 may besecured to structural members 93 on the jacket 52 through the use of anyappropriate connecting mechanism, such as U-clamps 95, for example, asshown in FIG. 6. The skid frame 92 is preferably clamped to the jacketbracing 93 by pipeline divers when the skid 70 is connected to thepipeline. The conduit 94 may be a section of pipe having a generallystraight or horizontal section 100 and a curved section 102. In aspecific embodiment, the conduit 94 may be a 3D or 5D induction bend.The particular curvature and dimensions of the conduit 94 will bedictated by the specific design and configuration of the platform 50 andjacket structure (e.g., grid layout of conductor slots 67), and may, forexample, bend only in one plane. In a specific embodiment, the inductionbend may be configured for three-dimensional reach to the desiredconductor slot 67. The flange end 98 may include a flange 104 suitablefor connection to a pipe line (not shown here) as will be understood bythose of ordinary skill in the art. The riser end 96 of the conduit 94is preferably provided with a diverless connector 106.

The connector 106 may be any type of diverless connector known in theart that can be used to remotely connect two sections of conduit locatedunderwater through the use of an ROV, some examples of which werepreviously provided above. In a specific embodiment, the connector 106may be a collet connector that includes hydraulic activation cylinders108 that are connected to one or more hydraulic fluid conduits 110contained within the umbilical 90. A video camera 112 may also bemounted adjacent the connector 106 (and/or on the skid 70 and/or jacket52) and connected to a video cable 114 contained within the umbilical90. The connector 106 may also be provided with a green fan laser 116,as will be understood by those of skill in the industry, atop theconnector 106 to assist in coaxial alignment of the connector 106 withthe conductor guides 67 through which the riser 68 is to be positioned,as more fully discussed below. In a specific embodiment, the green fanlaser 116 may be of the type available from Imenco AG of Haugesund,Norway, known as The Imenco Underwater Green Laser.

In this specific embodiment, the skid 70 is further preferably providedwith at least one air bladder or balloon, such as a first air bladder orballoon 118 and a second air bladder or balloon 120. The first bladder118 is preferably contained within a first enclosure 122 and the secondbladder 120 is preferably contained within a second enclosure 124. In aspecific embodiment, the enclosures 122 and 124 may be cages made withrigid or flexible steel mesh. The use of the enclosures 122/124 ispreferred to assist in avoiding the possibility of uncontrolled positivebuoyancy, as discussed above and as will be readily understood by thoseof skill in the art. The air bladders 118/120 may be remotely inflatedvia an air hose 126 contained within the umbilical 90. This allows forremote control from the deck of the in-water weight of the skid 70 tomaintain negative buoyancy (i.e., avoid the possibility of run-awaypositive buoyancy). In a specific embodiment, for example, the in-waterweight of the skid 70 maybe adjusted to approximately 500 pounds ordetermined to correspond to the ROV capacity.

The skid 70 is also preferably provided with a cable assembly 128 havinga load cell 130 and a ring eye 132. The load cell 132 is connected to anelectrical cable 134 contained within the umbilical 90 to provide areading to an operator at the deck of the in-water weight of the skid 70so that appropriate negative buoyancy can be maintained. The manner inwhich the skid 70 may be positioned will now be explained with referenceto FIGS. 9-11.

Positioning of the Tube Turn Skid

Referring now to FIG. 9, a cable 87 from a winch 89 maybe connected tothe ring eye 132 on the cable assembly 128 on the skid 70. The winch 89maybe connected to and supported by a platform crane 63 on the upperdeck 56 until the skid 70 is positioned near the point through which theskid 70 is to be passed through the platform jacket 52. As shown in FIG.10, the skid 70 is then transferred from the crane 63 to a number ofwinch lines 84 connected to winches 82. The winch lines 84 may be routedthrough the use of pulleys (e.g., pulley 85) mounted to the jacket 52and/or routed around jacket members. These lines are used to positionthe connector 106 on the tube turn skid 70 beneath the column ofconductor guides 67 through which the riser 68 is to be positioned. TheROV 86 may also be used to grasp the skid 70 and assist in locating itin its desired position relative to the jacket 52. With reference toFIGS. 11 and 12, additional winch lines 97 may be routed downwardlyadjacent to the selected column of conductor guides 67 and attached tothe riser end 96 of the conduit 94 on the skid 70 to assist inpositioning the skid 70. The green fan laser 116 (see, e.g., FIG. 6) ontop of the diverless connector 106 is then used in a known manner toshine a beam of visible light upwardly through the column of conductorslots 67 through which the riser 68 is to be positioned. In this manner,the exact desired location of the skid 70 may be established and theskid 70 can be precisely positioned so that the skid 70 can be leveledand the connector 106 can be engaged with the riser 68. In a specificembodiment, two circular plates (not shown) may be provided to assist inuse of the green fan laser 116. The plates are provided with a diameterto permit them to be placed by the ROV in the two conductor guides 67located immediately above the connector 106. The plates are preferablypainted white. The plate to be positioned in the guide 67 immediatelyabove the connector 106 preferably has a hole cutout (e.g., having adiameter of approximately three inches) in the center of the plate. Theplate to be positioned above the lower plate is preferably provided witha black or dark-colored crosshair marking. These plates thus cooperateto assist in using the green fan laser 116 to align the connector 106beneath the guides 67 for engagement with the riser 68.

Once the tube turn skid 70 is properly positioned, the next step is toconstruct and lower the riser 68 into position so that it can beattached to the tube turn skid 70 by the diverless connector 106. Thisis done through the use of the vertical stalking station 64, as will nowbe explained in connection with FIGS. 13-32. It is noted that, at thistime, the ROV 86 and/or winches 82 may be used to temporarily hang thecentralizers 74, for later installation, on the jacket bracing adjacentthe conductor slots 67 through which the riser string 68 is to belocated.

The Stalking Station

Referring to FIG. 13, in a specific embodiment, the stalking station 64may include a support base 136 attached to drilling deck skid beams 138on the upper or drill deck 56. As will be described more fully below,the support base 136 may comprise a pair of generally parallel I-beamspositioned on the deck skid-beams 138. The station 64 is positioned overthe empty column of conductor slots 67 through which the riser 68 is tobe lowered. The station 64 also includes a tower 140 that is hingedlyconnected to the support base 136 at a pivot point 142. The tower 140 ismoveable between a vertical position (as shown in FIG. 13) and ahorizontal position (as shown in FIG. 14). A hinged support arm 144 isconnected to the support base 136 and tower 140 to hold the tower in itsvertical position, and is collapsible to allow the tower 140 to move toits horizontal position. The tower 140 also includes a winch 146 (e.g.,a hydraulic winch) that controls a cable 148 that runs to the top of thetower 140 and over a pulley 150 and then down to a top clamp 152. Thetop clamp 152 includes rollers 186 and 187 to facilitate movement of thetop clamp 152 up and down along the tower 140, as more fully discussedbelow in connection with FIG. 28. The structure and operation of the topclamp 152 is more fully described below in connection with FIGS. 24-25and 28-32. The tower 140 also includes a horizontal joint support 154,the structure and operation of which is described more fully below inconnection with FIGS. 20 and 21. The station 64 also includes a bottomclamp 156 disposed on the support base 136. The structure and operationof the bottom clamp 156 will be described more fully below in connectionwith FIGS. 26-32.

The station 64 also includes a positive pressure welding habitat 158connected to a vertical support member 160 that is connected to thesupport base 136 and adapted for rotatable movement, as will be furtherdiscussed below, including in connection with FIGS. 22-23. The use ofpressurized enclosures and rooms is well known and customary on offshoreplatforms for safety reasons. The welding habitat 158 is supplied with apositive pressure air flow via an air duct connected to aremotely-located ventilator fan positioned a safe distance from anyareas where a potential leak or hazard might arise on the platform.Attached to the top of the tower 140 is an x-ray spider davit 141 thatis provided to lower an x-ray source inside the riser 68 to inspect eachweld as the riser sections 162 are welded together within the weldinghabitat 158. As mentioned above in connection with the size of the ROV86, the various components of the stalking station 64 should be designedand sized within the capacity of the crane 62 so that the crane 62 willbe able to lift the components to the deck surface from a supply boatfor assembly.

Assembling the Riser String

The vertical stalking station 64 is used to create the welded verticalriser string 68 (see FIG. 5) by welding together sections of riser pipeor conduit 162, such as shown in FIG. 15. The riser pipe sections 162are preferably coated with FBE or other suitable corrosion inhibitingcoating before the riser string 68 is constructed. With reference toFIG. 15, the conduit is depicted with a mating member 164 thatcorresponds to the diverless connector 106 on the tube turn skid 70(see, e.g., FIG. 6). Again, the present invention is not limited to anyparticular brand or style of diverless connector. Thus, the section ofconduit 162 shown in FIG. 15, with the mating member 164, is thelowermost section of the riser 68. This first, or lowermost, risersection shall be referred to by the numeral 162 a. All subsequentconduit sections 162 will be as shown in FIG. 15 except without themating member 164, and referred to by the numeral 162 b, etc. The upperend of each conduit section 162 is provided with a collar 166 adaptedfor mating engagement with the top clamp 152 on the tower 140 and thebottom clamp 156, as will be more fully discussed below. The lower endof the bottom riser section 162 a is temporarily capped so as to preventocean water from flowing up into the riser 68 as it is being loweredinto position, thereby eliminating the possibility of air flow at thewelding habitat 158 that could be caused by water surge or wave action.Temporarily capping the bottom of the riser string 68 also allows theriser string 68 to be partially filled with water from the deck level inorder to ballast the riser string 68 during the installation process,which may be more desirable with larger riser pipe diameters. The lowercap will be removed at a later stage after the riser 68 is positioned,preferably just prior to making the connection between the riser 68 andthe diverless connector 106.

As shown in FIG. 14, the tower 140 is shown in a lowered or generallyhorizontal position. The crane 62 is being used to position a section ofriser conduit 162 on the tower 140. The collar 166 on the riser pipe 162is engaged with the top clamp 152 and the horizontal joint support 154on the tower 140 is engaged with an opposite end of the riser pipe 162.FIG. 16 illustrates the crane 62 being used to lift the tower 140 fromits lowered position to its upright or generally vertical position. FIG.17 illustrates the tower in its upright position and the top clamp 152being lowered by the winch 146 to lower the riser pipe section 162relative to the bottom clamp 156. Note that after the lower end of theriser pipe 162 has passed through and is laterally supported by thebottom clamp 156, the horizontal joint support 154 is disengaged fromthe riser pipe 162 and moved out of the way into an open or retractedposition so as to allow the top clamp 152 to move downwardly past thejoint support 154. FIG. 20 illustrates the horizontal joint support 154in its closed or clamped position, and FIG. 21 illustrates thehorizontal joint support 154 in its open or retracted position. FIG. 18shows the top clamp 152 lowered all the way down adjacent the bottomclamp 156. The top clamp 152 is unclamped from the riser pipe 162 a andmoved back to the top of the tower 140 once the collar 166 on thesection of riserpipe 162 a is resting on the bottom clamp 156 in amechanically fail-safe position, as will be discussed and shown in moredetail below.

The next step is to load the next section of riser pipe 162 b onto thetower 140, in the manner explained above. The top of each section ofriser pipe 162 b etc. is preferably temporarily capped so as to preventthe loss of positive pressure in the welding habitat 158 during thewelding process, as more fully discussed below. Referring now to FIG.19, once the tower 140 is loaded with the next section of riser pipe 162b and moved into its upright position, the lower end of the risersection 162 b is positioned into coaxial alignment and contact with theupper end of the riser section 162 a being held by the bottom clamp 156to form a joint to be welded together. The manner in which the risersections 162 a and 162 b are coaxially aligned by the bottom clamp 156will be discussed and illustrated in more detail below. The weldinghabitat 158 is then rotated into a closed position so as to form apositive-pressure enclosure around the joint so that the two sections ofriser pipe 162 a and 162 b can be safely welded in a known manner. A topview of the welding habitat 158 in its closed position is shown in FIG.22. Once the field weld is completed, the welding habitat is moved intoan open position (see, e.g., FIGS. 18 and 23), and the x-ray spiderdavit 141 is used to inspect the welded joint. Assuming the weld passesinspection, the bottom clamp 156 is released, and the top clamp 152 islowered as explained above to lower the riser string 68 until the collar166 on the riser section 162 b is positioned into engagement with thebottom clamp 156. This process is repeated until the entire riser string68 has been constructed and the lowermost riser section 162 a ispositioned with the diverless mating connector 164 (see FIG. 15)positioned adjacent the diverless connector 106 on the skid 70 forengagement thereto through the use of the ROV and above-describedsurveillance equipment. As the riser string 68 is gradually constructedand lowered down through the conductor slots 67, it is preferred thattemporary wooden centralizers be positioned in the annulus between theriser 68 and at least some of the conductor guides 67 (preferably atleast the guides 67 just above and below the water line 60) to maintainstability of the riser string 68 during the installation process, and toespecially avoid excessive movement of the riser string 68 due to waveaction during the welding process.

Once the riser string 68 is connected to the connector 106, the nextstep is to conduct an industry standard hydrotest of the riser assemblywhile the riser string 68 is still being held in by the stalking station64. The top of the riser string 68 is capped and the riser is filledwith water and pressurized by a pump to a hydrostatic test pressure toconfirm no leaks in the assembly of the riser 68 and the skid 70. Thecentralizers 74 or hardenable filler material is then installed at eachconductor guide 67 using the ROV 86. The temporary friction clamp 78 isthen clamped to the riser 68 at the lower or production deck level 58 tosecure the riser 68 until a mechanical contractor executes the finaltie-in to the production manifold. At a later time, pipelineinstallation divers may secure the skid 70 to the jacket 52, such aswith U-clamps 95, as shown in FIG. 6, and reinstall any jacket anodes atthe same time the flange 104 on the skid 70 is attached to the pipelineon the ocean floor 54.

The Top and Bottom Clamps

Specific embodiments of the top clamp 152 and the bottom clamp 156 onthe vertical stalking station will now be described. Referring to FIG.24, a specific embodiment of the top clamp 152 is shown in an openposition. The top clamp 152 may include a frame 170 with a pair ofclamping arms 172 and 174 hingedly attached thereto. Each clamping arm172/174 includes a curved clamping surface 176/178 sized for matingengagement with the riser pipe 162. The top clamp 152 further includesany suitable mechanism for moving the arms 172/174 between open andclosed positions. For example, in the specific embodiment shown in FIG.24, the top clamp 152 may be provided with a jack screw 180 attached tothe arms 172/174 via threaded flange members 182 and 184, in a knownmanner. The top clamp 152 is also preferably configured for rollingengagement with the tower 140 of the vertical stalking station 64. Asshown in FIG. 24, the tower 140 may be an I-beam. The top clamp 152 mayinclude an outer roller 186 disposed between the frame 170 and the tower140. The top clamp 152 may further include one or more inner rollers 188positioned to engage an inner surface of the tower 140 such that the topclamp 152 is engaged with or connected to the tower 140 to permitrolling movement of the top clamp 152 up and down the tower 140. Asshown in FIG. 28, discussed further below, the top clamp 152 ispreferably provided with a set of upper rollers 186/188 and a set oflower rollers 187/189. FIG. 25 is similar to FIG. 24, except that FIG.25 shows the top clamp 152 in its closed or clamped position, with theclamping surfaces 176/178 clamped around the riser pipe 162.

Referring now to FIG. 26, the bottom clamp 156 may include a pair ofclamping arms 190 and 192 configured for slidable engagement with thesupport base 136 of the stalking station 64. With reference to FIG. 31,the clamping arm 190 is shown in cross-section, and it can be seen fromthis view that the support base 136 may comprise a pair of generallyparallel I-beams 194 and 196. It can further be seen from FIG. 31 thatthe clamping arms 190/192 each includes a lower lip 198 that defines aslot 200 to allow for sliding engagement of the arms 190/192 with theI-beams 194 and 196. The slots 200 are further preferably sized to allowfor sufficient lateral movement of the arms 190/192 relative to thebeams 194/196 for purposes of co-axial alignment of sections of riserpipe 162 to be welded together, as discussed in more detail below.

Referring again to FIG. 26, corresponding opposed ends of the arms190/192 are connected to screw jacks 202/204 and configured to movebetween an open position (as shown in FIG. 26) and a closed position (asshown in FIG. 27). Each arm 190/192 further includes an arcuate ledge206/208. In operation, as shown in FIG. 29, when the top clamp 152lowers a section of riser pipe 162 down through the bottom clamp 156,the arms 190/192 are moved towards each other by the screws jacks202/204 into a position such that the collar 166 on the riser pipesection 162 will rest on the arcuate ledges 206/208. The purpose of theclamping arms is not to clamp and hold the riser string 68, but insteadto position the arcuate ledges 206/208 so as to support the collar 166.In this way, a mechanical fail safe connection is provided to hold theriser string 68. In other words, the riser string 68 is not susceptibleto being dropped due to failure of a transverse clamping mechanism. Oncethe riser pipe collar 166 is securely resting on the arcuate ledges206/208, and the top clamp 152 has been withdrawn to retrieve anothersection of riser pipe 162, the riser pipe 162 hanging in the arms190/192 can be moved around as needed to position it in co-axialalignment with the next section of riser pipe to which it is to bewelded. Side-to-side, or lateral, movement is accomplished through theuse of a lateral positioning mechanism, such as a lateral hydrauliccylinder 210 that may be connected to the support base 136 and the arm192. The bottom clamp 156 may further be provided with one or moretransverse or rotational positioning mechanisms, such as hydrauliccylinders 212 and 214, which are connected to the support base 136 andthe arms 192 and 190, respectively. If both cylinders 212 and 214 areactuated in unison, then both arms 190/192 will move transverselytogether along with the pipe 162. But if only one of the cylinders212/214 is actuated or if they are actuated in different directions thenrotational movement will be imparted to the riser pipe 162.

Stabilizing the Riser in the Guides

Details of a specific embodiment of the centralizers 74 will now bedescribed with reference to FIGS. 33-36. Referring to FIG. 33, a sideview of a pair of centralizer segments 74 a and 74 b is shown in aspaced apart position. FIG. 34 is a top view of the segments 74 a/74 bas shown in FIG. 33. Each segment 74 a/74 b includes a curved surface216 a/216 b adapted for engagement around the riser string 68. Eachcurved surface 216 a/216 b is preferably lined with a suitable material(e.g., neoprene) to electrically isolate the riser 68 from the jacket52. FIGS. 35 and 36 illustrate the centralizer segments 74 a and 74 binstalled in a conductor slot 67 with the riser 68 positionedtherethrough. It can be seen from the side profile shown for example inFIG. 36 that the segments 74 a/74 b may form a funnel and be adapted formating engagement with the conductor slot 67.

An alternative approach to stabilizing the riser 68 in the guides 67and/or electrically isolating the riser 68 from the platform 52 will nowbe discussed in connection with FIGS. 37-40. Referring initially toFIGS. 37 and 38, an annular bladder 218, such as an elastic latexbladder, shown here in an empty or collapsed form, maybe attached to ametal deployment ring 220. The ring 220 should be of sufficient weightto pull the bladder 218 down through the water. The annular bladder 218is sized to fit around the riser 68. A pair of polypropylene ropes 222are attached to the ring 220 and used to lower the bladder 218 intoposition adjacent the conductor guide 67. The ROV 86 is used to monitorproper positioning of the bladder 218 relative to the guide 67. Once inposition, an injection hose 224 running from deck level is inserted intoan aperture 219 in the bladder 218 and used to inject a hardenable orsettable material into the bladder 218 so as to fill up with annulusbetween the guide 67 and the riser 68, as shown in FIGS. 39 and 40. Thefiller material may be of any type (e.g., grout, epoxy, etc.) that couldbe used to fill the bladder and stabilize the riser 68 within the guides67. At least the inner diameter of the ring 220 is preferably coveredwith an insulating material (e.g., neoprene) so that the riser 68 iselectrically isolated from the guides 67. The bladder 218 is alsopreferably made of a material (e.g., latex) that will electricallyisolate the riser 68 from the guides 67. Once the bladder 218 is filledto the desired level, the ROV 86 may be used to cut the ropes 222 andhose 224, the loose ends of which may then be retrieved to deck level. Abladder 218 for each guide 67 is preferably positioned over the riserstring 68 just before the uppermost riser section 162 is welded to theriser string 68, and then the bladders 218 are preferably lowered intoposition and filled after the hydrostatic pressure test is successfullycompleted.

From the above description it can be seen that by employing the presentinvention a riser can be installed on an existing operational offshoreplatform without terminating production, thereby avoiding economic lossassociated with production downtime. Use of the present inventionfurther eliminates expensive delays with marine equipment and diveroperations due to unpredictable strong ocean currents and rough seastates. Use of the present invention further results in better controlof interfacing schedules of offshore contractors, and expensivemobilization of marine equipment is also avoided. In addition, with thepresent invention, the riser can be installed and tested before pipelineinstallation equipment is mobilized. There are also safety benefitsprovided by the present invention insofar as it is not necessary tounduly subject divers and marine support vessels to potentially adversecurrents or sea states. It can also be seen that the present inventionis implemented pursuant to industry standard safe and high qualityprocedures for hydrocarbon producing environments. Another advantage ofthe present invention is that the riser sections are welded, as opposedto bolted, together, thereby resulting in better connections between theriser sections such that the joints are less susceptible to leakage.

It is to be understood that the invention is not limited to the exactdetails of construction, operation, exact materials or embodiments shownand described, as obvious modifications and equivalents will be apparentto one skilled in the art. It is also noted that although one benefit ofthe invention is the ability to install a riser to a platform withoutceasing production, the invention is not limited to riser installationswhere production is not terminated during the installation process.Accordingly, the invention is therefore to be limited only by the scopeof the appended claims.

1. A method of establishing a fluid flow path from a deck of an offshoreplatform supported by a jacket to a pipeline located in a body of waterbeneath the deck, comprising: positioning a conduit in the body of waterbelow the deck, the conduit having a first end located within the jacketand a second end located outside of the jacket; constructing a riserhaving an upper end and a lower end; positioning the riser within thejacket with the upper end located at the deck; and connecting the lowerend of the riser to the first end of the conduit.
 2. The method of claim1, further including performing each of the steps without ceasingproduction operations of the platform.
 3. The method of claim 1, furtherincluding connecting the second end of the conduit to the pipeline. 4.The method of claim 1, further including establishing fluidcommunication between the upper end of the riser and a source ofhydrocarbons below the body of water.
 5. The method of claim 1, furtherincluding positioning the riser within a plurality of conductor guideson the jacket.
 6. The method of claim 5, further including stabilizingthe riser within the conductor guides.
 7. The method of claim 5, furtherincluding positioning a pair of generally semi-circular shapedcentralizer members in an annulus formed between the riser and eachconductor guide.
 8. The method of claim 5, further including filling anannulus between the riser and each conductor guide with a material andallowing the material to set.
 9. The method of claim 8, wherein thematerial is at least one of a grout and an epoxy.
 10. The method ofclaim 1, further including electrically isolating the riser from thejacket.
 11. The method of claim 1, wherein connecting the lower end ofthe riser to the first end of the conduit is performed without the useof a diver.
 12. The method of claim 1, wherein connecting the lower endof the riser to the first end of the conduit is performed with aremotely operated vehicle.
 13. The method of claim 1, further includingconnecting at least one inflatable bladder to the conduit and remotelycontrolling the pressure in the bladder to assist in positioning thefirst end of the conduit adjacent the lower end of the riser conduit.14. The method of claim 13, further including an enclosure containingthe inflatable bladder.
 15. The method of claim 1, further includingusing a diverless connector to connect the lower end of the riser to thefirst end of the conduit.
 16. The method of claim 1, further includingusing a light source to align the lower end of the riser with the firstend of the conduit.
 17. An apparatus for connecting a generally verticalriser within a jacket of an offshore platform to a pipeline locatedoutside of the jacket, comprising: a frame; and a generally L-shapedconduit attached to the frame, the L-shaped conduit having a first endadapted for connection to a lower end of the riser conduit and a secondend adapted for connection to the pipeline.
 18. The apparatus of claim17, further including at least one remotely-controllable inflatablebladder adapted to assist in positioning the first end of the conduitadjacent the lower end of the riser.
 19. The apparatus of claim 17,further including a diverless connector connected to the first end ofthe L-shaped conduit and a mating connector connected to the lower endof the riser.
 20. An apparatus for constructing a riser comprising: asupport base; a tower rotatably attached to the base and moveablebetween a lower position and an upper position; a top clamp movablyattached to the tower; a bottom clamp attached to the support base, andaligned with the top clamp when the tower is in its upper position; andan enclosure having an open position and closed position, the enclosurebeing positioned between the bottom clamp and the top clamp when theenclosure is in its closed position.